Small and micro scale processes, including processes utilizing certain portable equipment, are described in detail in U.S. application Ser. No. 12/040,500 filed on Feb. 29, 2008, entitled “Fischer-Tropsch and Oxygenate Synthesis Catalyst Activation/Regeneration in a Micro Scale Process,” the disclosure of which is incorporated by reference herein in its entirety.
As used herein the terms “natural gas” and “NG” are used to refer to natural gas, methane or combinations thereof. The terms “natural gas” and “NG” are used to refer to such compositions irrespective of the source. Thus, the terms “natural gas source,” “natural gas resource,” “natural gas well,” “natural gas field,” “NG source,” “NG resource,” “NG field,” and “NG well” refer to any source of natural gas or methane including by way of example, natural gas wells, associated gas wells, gas condensate wells, shale gas wells, landfill gas (LFG) sources, coal bed methane (CBM) wells, and gas hydrate deposits.
In conventional land-based Gas-to-Liquids (GTL) processes, the terms “stranded-” or “remote” gas typically have negative implications. First, as suggested by the descriptions, the gas is typically physically removed from potential markets. Second, conventional economic analyses indicate that economies of scale require relatively large plants in order to generate acceptable returns on investment. Although there is some variability, the minimum economically viable size of a conventional Fischer-Tropsch (FT) based GTL plants is typically in the range of 10,000-20,000 barrels per day (bbl/d) hydrocarbon liquid product, or greater (often >50,000 bbl/d). FT GTL plants recently built or currently under construction have capacities of about 34,000 bbl/d (Sasol “Oryx” in Qatar) and about 140,000 bbl/d (Shell “Pearl” in Qatar). A plant having a smaller capacity (e.g., 10,000 bbl/d hydrocarbon liquid product) with an assumed high conversion efficiency of only 8,000,000 BTU per barrel of oil equivalent product, would require at least 80,000,000,000 BTU/day synthesis gas (“syngas”) feed. At an assumed gas composition consistent with 1,000 BTU per standard cubic foot (“SCF”) of natural gas (“NG”) this production rate would require 80,000,000 SCF/day (“SCFD”) of feed NG, which is considered a large production requirement. Comparable rates for larger plants would be almost 300 million SCFD to produce about 34,000 bbl/d liquid product and about 1.1 billion SCFD to produce about 140,000 bbl/d hydrocarbon liquid product.
Similarly, in order to achieve acceptable returns on investment, large chemical processing plants such as those employed for GTL are generally expected to operate for at least 20, and more commonly, 30 years. Assuming a 20 year plant life and 350 operation days per year, the total feedstock requirements for a 10,000 bbl/d hydrocarbon liquid product plant would be in the range of 560 billion cubic feet (0.56 trillion cubic feet, or “TCF”). For a 20,000 bbl/d plant with a 30 year life, the total feed would increase to about 1.7 TCF. Plants having the capacity of the Sasol “Oryx” plant or the Shell “Pearl” plant would require about 3 and over 11 TCF, respectively, assuming 30 year plant lives.
Methanol synthesis is much more common today than Fischer-Tropsch synthesis. Historically (generally up to about 1990) methanol synthesis plant sizes have been rather smaller, in the range of 10,000 to 1,000,000 metric tons of product per year. This corresponds to approximately 230 to 23,000 bbl/d methanol product. The majority of methanol synthesis plants based on NG feedstocks constructed since about 1990 have been larger, in the range of 500,000 to 2,000,000 metric tons/year (11,000 to 45,000 bbl/d of methanol), again for economic reasons identical to those for FT based plants. Unlike conventional crude oil or Fischer-Tropsch based hydrocarbon products, methanol contains substantial oxygen (approximately 50% by weight); therefore its energy density is almost a factor of 2 lower and about twice as many barrels of methanol (as compared to FT hydrocarbons) can be produced from a given quantity of NG feed. Thus a 45,000 bbl/d methanol synthesis GTL plant is more or less comparable in feedstock requirements to a 20,000 bbl/d FT based GTL plant. In the following GTL plant volumetric production rates will be based on hydrocarbon products and energy densities, it being understood that for methanol synthesis based processes the volumetric production rates will be approximately a factor of 2 larger.
Table 1 and FIG. 1 show representative distributions of known natural gas fields, including fields considered remote, stranded, not remote and not stranded (Table 1 includes only fields outside of North America as of 1992 (Ivanhoe, L. F., Leckie, G. C., “Global Oil, Gas Fields, Sizes Tallied, Analyzed”, Oil and Gas Journal, Feb. 16, 1993)). As shown in Table 1, there are only about 100-200 fields with reserves consistent with the larger conventional land-based GTL plants. The number of fields with sufficient reserves that are stranded and/or remote, such that the gas cost would be low enough to justify a GTL plant, is significantly smaller. Most of the largest stranded fields are prime candidates for gas monetization by production of liquefied natural gas (LNG), a more technologically developed process than GTL; for this reason LNG is generally perceived as being significantly less risky than GTL and is, therefore, much more common commercially.
TABLE 1Natural Gas Field Size (TCF)NumberBetween 50 and 50015Between 5 and 5071Between 1 and 5234Between .5 and 1269Between .25 and .5276Between .1 and .25475Between .01 and .11,195Less than .011,913
Table 1 and FIG. 1 also show that there are a much larger number of smaller fields, which are too small to accommodate the natural gas feed rates economically required by very large, long life land-based GTL or LNG facilities.
There have been a number of proposals for mobile, marine based GTL plants, typically at somewhat smaller sizes—1,000-20,000 bbl/d hydrocarbon liquid product—mounted on platforms, barges, and/or floating production, storage and offloading/offtake (“FPSO”s) ships. Because such facilities would be movable, smaller natural gas fields could be converted to liquid products with these units. For a 1,000 bbl/d unit hydrocarbon liquid product production rate, a feed rate of at least 8-10 million SCFD (MMSCFD) would be required. To supply such a production unit for five (5) years, a natural gas field would have to supply 14 billion standard cubic feet (or 0.014 TCF) natural gas. Such units could greatly expand the monetization of stranded marine/offshore natural gas, but would not address the problem of small onshore stranded and/or remote gas resources. In addition, offshore environments can be relatively challenging to conventional refinery/chemical plant processes due to considerations such as wave motions, limited surface/plot areas, and limitations on maximum vessel height and weight. Currently, such proposed processes have not been successfully commercially developed.
In order to be fully movable and/or transportable on shore, a GTL plant would need to be smaller than even 1,000 bbl/d hydrocarbon liquid product capacity. Actual size would be highly dependent on the specific technologies employed and their packaging, but the maximum size is almost certainly smaller than 1000 bbl/d, and probably as small as 200 bbl/d hydrocarbon liquid product, for units that would be transportable by conventional trucking methods. GTL plants at this scale have been constructed and operated by a number of companies, including ExxonMobil, ConocoPhillips, Sasol, BP, and Syntroleum, and have generally been referred to as Process Development, or Demonstration, Units (“PDU”s). Despite their small size (between 50 and 400 bbl/day hydrocarbon liquid product), such constructed units have all been: (1) too large to be readily transportable; and (2) uneconomic except for R&D purposes. Specifically, capital costs for these “PDU”s have been in the 20 to 50 million dollar range, or higher, with the net operating costs in the range of millions to tens of millions of dollars per year. In general, such PDUs were operated for a few years to provide process scale-up data, and then shut-down or mothballed at least as soon as possible once these programs were completed.
An additional issue in economically monetizing small natural gas supplies—aside from low total reserves (i.e., leading to short production life) and relatively low flow rate (i.e., small capacity plants)—is the tendency of the maximum NG production rate of gas sources, of any total size, to change over time. In fact the gas production rate often changes significantly over the life of the resource or field. FIGS. 2-4 show typical natural gas production rates versus time for traditional gas field wells, landfill gas (LFG) sources, and coal bed methane (CBM) wells, respectively.
FIGS. 2-4 indicate that the NG production rate from any of these sources is almost never constant, and typically declines, often significantly and rapidly. In addition, NG production generally increases significantly early in the life of a field or landfill, often over a period of months or even years, and then may increase again during subsequent source treatments, such as well fracturing, refracturing, or other workover or stimulation treatments, later in the life of the well. In general, the rate of NG production decline is larger for smaller fields, so that low production rate wells with short productive time spans typically go hand in hand.
Generally, large processing plants are built in parallel units, commonly referred to as “trains.” The trains are typically sized either by feedstock availability, total cost, or maximum size of particular parts of the process equipment. For GTL plants all three limitations are possible. Natural gas field size or stable production rate, and total capital cost exposure or risk are the most common limitations of the first two types. Either synthesis gas generation equipment (typically reactors) and/or maximum oxygen plant train size are the common limitations of the third type. For large plants additional trains may be added, but, historically, are almost never removed, while capacity is expected to be constant or increasing with time, although economic considerations (e.g. monetary losses) may result in the shutting down (“mothballing”) of one or more (or all) trains. The decrease in NG production which normally occurs in each and every well is countered by bringing additional production wells into service on a more or less continuous basis, such that total field/resource NG production is more or less constant or even increasing to meet demand until the resource/field itself is depleted.
When considering monetizing small gas resources, the typical decline in well NG production is more problematic because the micro-GTL plants are sized to handle the production from only a small number of wells, in the range of between about 1 and about 20 wells. Constant NG feedstock production from the well(s) is therefore unlikely. It may be possible to limit the NG production from a single well to match the capacity of an installed micro-GTL unit. Such a scenario, however, is less attractive for the resource owner who would prefer to operate at the highest possible production rate consistent with reservoir integrity to maximize cash flow. U.S. Pat. No. 7,067,561 describes a multi-train GTL plant whereby the overall capacity can be adjusted to match available feed by closing off trains. While the process described in U.S. Pat. No. 7,067,561 would allow maximum NG production and monetization as production naturally declines, the overall economics of the project would suffer, as the entire GTL unit would be underutilized for a significant fraction of the life of the field. In practice, some limitation on field production rate—typically in the range of 50% of maximum NG production rate—may be required in order to provide for relatively constant gas flow, but production should be maximized consistent with this general requirement.
When a new NG resource is suspected or discovered, tests to measure the capacity of the resource prior to making the decision to install relatively costly gas gathering, treatment, and transportation (pipeline or other) facilities are generally conducted. Otherwise, it may later be discovered that the NG resource was too small to justify the investment. For NG fields such testing typically entails drilling a number of wells around the suspected extent of the field and then producing NG for as long as several years to measure the long term production performance (i.e. “decline curves”) of each well. In the absence of gathering, treatment, and transportation infrastructure, gas produced during these tests is usually flared, re-injected, or, less commonly, vented. This is especially common in newly discovered NG sources, where conventional transportation infrastructure, especially pipelines, may be entirely absent. The lost value of this production test NG can be measured in the millions of dollars. Should these tests indicate sufficient total field size and production rates to justify the investment, NG gathering, treatment, and transportation (e.g. pipeline) facilities may then be installed. Similarly, even in the presence of an existing gas transportation pipeline, for example, connection charges to such existing facilities may be so high as to require multiple well decline curve tests/measurements to justify the connection expense. Thus, even relatively large NG resources located close to substantial markets (in other words, gas that would not normally be considered stranded) may, in fact, be stranded for a period of time, often measured in years, during initial field development and well testing.
It would be extremely beneficial if a low capital and operating cost, fully transportable and/or movable technology platform existed that could economically monetize small stranded NG fields or other sources (i.e. landfill gas) on shore.